Retrievable well packer apparatus



Nov. 26, 1968 D. E. YOUNG 3,412,801

RETRIEVABLE WELL PACKER APPARATUS Filed Nov. 5, 1966 5 SheetsSheet 1.Dawc/ 5. young INVENTOR.

55 ATTORNEY 3 Sheets-Sheet 2 fla /0 5. young INVENTOR.

qrromvsv D. E. YOUNG RETRIEVABLE WELL PACKER APPARATUS Nov. 26, 1968Filed Nov.

D. E. YOUNG Nov. 26, 1968 RETRIEVABLE WELL PACKER APPARATUS 3Sheets-Sheet 5 Filed Nov. 6, 1966 flay/a 15. 700/7 INVENTOR.

ATTORNEY United States Patent 3,412,801 RETRIEVABLE WELL PACKERAPPARATUS David E. Young, Houston, Tex., assignor to SchlumbergerTechnology Corporation, Houston, Tex., a corporation of Texas Filed Nov.8, 1966, Ser. No. 592,803 25 Claims. (Cl. 166120) ABSTRACT OF THEDISCLOSURE Well packer apparatus for use in a well bore including a bodymember, slip and expander means for anchoring against movement andexpansible packing means for sealing off the well bore, a closablebypass passage extending between said body member and said packingmeans, and hydraulically operable means connected to said expander meansand responsive to differences in fluid pressures above and below saidpacking means for exerting downwardly directed force on said expandermeans.

This invention relates generally to subsurface well tools and moreparticularly to a new and improved well packer for use in a wellconduit.

To perform production operations in a well, an apparatus commonly calleda packer can be lowered into a cased well bore on a tubing string. Thepacker has a pliant and deformable sealing element which can be expandedagainst the well casing to prevent vertical movement of fluids past itssealing point. Normally, the packer will also have casing grippinganchors which can engage the casing to prevent any substantial verticalmovement of the packer itself. The tubing string on which the packer islowered into the well bore provides a flow conductor for transportingformation fluids to the surface from regions below the packer.

During production of a well, the pressrue of fluids within thecasing-to-tubing annulus may exceed the pressure of fluids in the tubingstring. For example, a relatively heavy control fluid may remain in theannulus after the packer is set and while formation fluids are beingconducted through the tubing string to the surface. The hydrostaticpressure of the control fluid can impose a downward force on the packerstructure tending to move the packer structure downwardly in the casing.Also, the well may be swabbed by artiflcally lifting fluids in thetubing string toward the surface, thereby reducing the pressure withinthe tubing string to a value lower than the annulus pressure. In eithercase, the higher pressure in the annulus exerts a downward force on thepacker structure. On the other hand, the pressure of fluids within thetubing string and below the packer may exceed annulus pressures. Forexample, the pressure of fluids below the packer in a dual completionwell can be higher than those in a zone above the packer. Also, theremay not be any fluids in the annulus, in some cases, so that fluidsbelow the packer exert upward pressure on the packer. Moreover, thehigher pressures during water flooding or other injection operations,which can be carried out using a production packer, can act from belowthe packer as forces in an upward direction.

The net force in either direction tends to cause the well packer to moveor shift within the casing. Any substantial movement in either directionis undesirable because such movement may cause the tubing to part orcause the packer to become unseated.

Moreover, it is desirable that well packers of the type described beprovided with a fluid bypass and pressure equalizing means to facilitateinsertion into a fluid-filled well bore and equalization of fluidpressures across the tool when desired. Prior art devices have resortedto a fluid bypass which is a separate tool from the packer, and which islocated in the tubing string above the packer. This type of fluid bypassimposes several limitations. During extended periods of fluid flow,normally suspended solid particles in fluids in the annulus may settleon top of the well packer, and hinder proper operation when it isdesired to retrieve the packer to the surface. Also, plugging substancessuch as sand may build up within the bore of the packer and within thetubing string above the packer so that a fluid bypass located at thispoint will not operate properly to equalize tubing-to-annulus pressuredifferentials when it is desired to retrieve the well packer. Anadditional tool in the pipe string can also add to the complexity ofsurface manipulations required to operate the tools and thereby increasethe probabilities of malfunction.

An object of the present invention is to provide a new and improvedfull-bore retrievable well packer for effecting an annulus seal betweena tubing and a well conduit.

Another object of the present invention is to provide a new and improvedwell packer of the type described having only a single anchor mechanismyet which will remain immovably anchored in a well when subjected topressures from either above or below.

Yet another object of the present invention is to provide a new andimproved well packer of the type described having an integral fluidbypass and pressure equalizing means which can be positively operated toequalize pressures across the packing element and through which fluidscan be circulated to wash away any sediment above the well packer orplugging substances within the packer itself. Moreover, fluid pressuredifferences across the packing element can be equalized so that thepacker can be retrieved even though the bore therethrough has becomeplugged with sand or other plugging substances.

Briefly, a well packer apparatus in accordance with the concepts of thepresent invention includes a sleeve member having an external recess andan elastomer packing element in the recess adapted for expansion to sealagainst a surrounding well conduit wall. A tubular body member ismovable within the sleeve member and is arranged to provide a fluidpassage space exteriorly of the body member and interiorly of the sleevemember. A passage closing means is normally open and can be operated bylongitudinal movement of the body member for closing off the passagespace. Anchors on the body member are normally retracted and can beexpanded by an expander against the well conduit wall to anchor the wellpacker against movement, Hydraulic means are connected to the expanderand are responsive to pressure differentials across the expanded packingelement for exerting force on the anchors in a direction to hold theanchors engaged. Another passage around the passage closing meanscommunicates the hydraulic means with well annulus pressures even thoughthe passage closing means is closed.

The present invention has other objects and advantages which will becomeapparent in connection with the following detailed description thereof.The novel features of the present invention are set forth withparticularity in the appended claims. The invention, both as to itsorganization and manner of operation, may be best understood by way ofillustration and example of an embodiment thereof when taken inconjunction with the accompanying drawings, in which:

FIGURE 1A is a longitudinal section, with portions in side elevation, ofthe upper portion of the well packer embodying principles of the presentinvention and with parts in retracted positions;

FIGURE 1B is a view similar to FIGURE 1A of the lower portion of thewell packer and forms a lower continuation of FIGURE 1A;

FIGURE 2A is a longitudinal section, with portions in side elevation, ofa well packer in accordance with the present invention set in a wellcasing:

FIGURE 2B forms a lower continuation of FIG- URE 2A;

FIGURE 3 is a cross section taken on line 3-3 of FIGURE 13;

FIGURE 4 is a cross section taken on line 44 of FIGURE 1B;

FIGURE 5 is a cross section taken on line 5-5 of FIGURE 4;

FIGURE 6 is a fragmentary sectional view of the drag mechanism of thepresent invention; and

FIGURE 7 is a fragmentary sectional view of modified construction of thepresent invention.

Referring to FIGURE 1, a well packer 10 embodying the principles of thepresent invention includes a tubular body member or mandrel 11 whichextends throughout the length of the well packer and which has a bore 12therethrough providing a fluid passageway. The upper end of the mandrel11 is connected to a sub 13 with a threaded box portion to which thelower end of a tubing string 14 may be connected. The lower end portionof the mandrel 11 can be threaded as at 15 for coupling to a string ofpipe or another well tool. The bore 12 of the mandrel 11 can have aninner diameter at least as great as the drift diameter of the tubingstring 14 to provide an unrestricted passageway therethrough. An annularsleeve member 16 is provided on the sub 13 and has an inner surfacelaterally spaced from the outer periphery of the mandrel 11 to providean annulus 17 therebetween. Several side ports 18 in the sleeve member16 communicate the annulus 17 with the exterior of the sleeve member 16.

An annular compression sleeve 20 surrounds the mandrel 11 and has anoutwardly extending flange 21 intermediate its ends. An elastomericpacking structure 22 is mounted around the compression sleeve 20 withits lower end abutting against the flange 21 and its upper end abuttingagainst an abutment ring 23. Although the packing structure 22 can takeany desired form, it is shown for convenience of illustration ascomprising several rubber or elastomer rings 24 separated by spacerrings 25. The abutment ring 23 is slidably mounted on the compressionsleeve 20 and has an upwardly facing recess 26 which can contain asuitable thrust bearing 27. An snap ring 28 in the compression sleeve 20engages the upper face of the bearing 27 to limit upward movement of theabutment ring 23 along; the compression sleeve. It will be appreciatedthat advancement of the abutment ring 23 along the compression sleeve 20toward the flange 21 will serve to compress the packing rings 24 andexpand them outwardly.

The inner periphery of the compression sleeve 20 is laterally spacedfrom the outer surface of the mandrel 11 so that an annular fluidpassageway 30 is formed therebetween for bypassing fluids around thepacking structure 22. An annular valve head 31 is provided forcontrolling fluid flow through the bypass passageway 30. The valve head31 can be in the form of a sleeve which is coupled to the mandrel 11 sothat it can be moved longitudinally by the mandrel, the coupling being,for example, threads 32. The upper end portion 33 of the sleeve 31 is ofenlarged section and has an annular groove 34 in its outer surface whichreceives a suitable sealing element 35. An inner shoulder 36 on thecompression sleeve 20 normally engages the upper end of the valve head31 to limit downward movement of the compression sleeve 20 along themandrel 11.

An annular portion 38 of the compression sleeve 20 extends downwardlyover the valve head 31 and has an internal annular recess 39 formedadjacent to the enlarged portion 33 of the valve head when the parts arein the relative positions shown in FIGURE 1A. The inner surface 40 ofthe lower portion 38 below the recess 39 is laterally spaced from thelower portion of the valve head 31 to form a fluid passage space 41which continues the bypass passageway 30. The inner surface 40 is alsosized relative to the valve head seal element so that when the valvehead 31 is moved downwardly relative to the compression sleeve 20, theseal element will seal against the surface to close the bypasspassageway to fluid flow. The valve head 31 can have a plurality ofradially cut slots 42 in its upper end through which fluids can flowwhen the seal element 35 is adjacent to the recess 39.

An annular hydraulic member 45 is slidably received on the lower portionof the valve head 31 and a suitable seal, for example an O-ring '46,seals between the hydraulic member and the outer periphery of the lowerportion. The inner diameter of the hydraulic member 45 can be sized suchthat an outwardly extending shoulder 47 on the mandrel 11 can engage thelower face 48 of the hydraulic member 45 to limit its downward movementrelative to the mandrel. Extending upwardly from the hydraulic member 45is a connector sleeve 49 which can be slidably disposed on the lowerportion 38 of the compression sleeve 20, the upper end of the connectorsleeve extending into engagement with the compression sleeve flange 21.A lug 50 can extend into an elongated slot 51 in the sleeve 49 tocorotatively secure the compression sleeve 20 and the hydraulic member45 to one another. A plurality of side ports 52 extend through the wallof the connector sleeve 49 above the hydraulic member 45 to communicatethe bypass passageways 30, 41 with the exterior of the well packer belowthe packing structure 22.

A sleeve member 55 is threadedly coupled to the hydraulic member 45 anda suitable seal element 56 makes the connection fluid tight. The sleevemember 55 extends downwardly in a manner to form an annulus 57 relativeto the mandrel 11 and its lower end is attached to a generallyfrusto-conically shaped expander cone 58. The expander cone 58 has abore 59 which is sized for sliding reception on the mandrel 11 and hasouter inclined surfaces 60 which converge downwardly and inwardly towardthe mandrel 11.

An annular, floating piston member 62 is movably received within theannulus 57. Suitable seal elements 63 and 64 seal between the innerperiphery of the piston member 62 and the outer surface of the mandrel11, and between the outer periphery of the piston member 62 and theinner surface of the sleeve member 55, respectively. It will beappreciated that a chamber 65 is formed between the piston member 62 andthe hydraulic member 45. Upward movement of the floating piston member62 is limited by its engagement with the mandrel shoulder 47 anddownward movement is limited by engagement with the upper face 66 of theexpander cone 58.

The chamber 65 is placed in fluid communication with the well annulusabove the packing structure 22 so that pressures in the well annulus canact on the lower face of the hydraulic member 45 and on the upper faceof the floating piston member 62. To accomplish this, the valve head orsleeve 31 is coupued to the madnrel 11 so that its lower end 67 isspaced a small distance away from the outwardly extending shoulder 47 onthe mandrel 11. A pressure communicating passage 69 is provided betweenthe sleeve 31 and the mandrel 11 and can be a plurality ofcircumferentially spaced grooves 68 which extend along the length of thesleeve 31 and through the threads 32. The passage 69 and the spacebetween the end of the sleeve and the upper face of the shoulder 47thereby function to communicate fluid pressures to the chamber 65 fromthat portion of the bypass passage-way 30 located above the valve headseal element 35. As previously pointed out, the bypass passageway 30 isin communication with the well annulus above the packing structure 22via the sleeve annulus 17 and the side ports 18 in the sleeve member 16.Therefore, it can be appreciated that pressures of fluids in the annulusabove the packing 22 are always reflected in the chamber 65 whether thevalve head 31 is in its bypass opening or closing position.

As shown in FIGURE 1B, a tubular cage member 70 is carried by the lowerend portion of the mandrel 11 with its lower end normally engaging astop ring 71 on the mandrel. An internal annular recess 79 in the cagemember 70 can be sized to slidably receive the lower end of a stopsleeve 53 which extends upwardly and can be joined to the expander cone58 by threads 54. The stop sleeve 53 functions to limit upward movementof the expander cone 58, the hydraulic member 45 and the compressionsleeve 20 along the mandrel 11 so that the valve head 31 can not closethe bypass passageway 30, 41 while the parts of the well packer are intheir normally retracted positions. Referring momentarily to FIGURE 6,the cage member 70 can have a plurality of circumferentially spaced,radially directed recesses 72, each of which receives a conventionaldrag block 73. The drag blocks 73 are pressed outwardly by compressionsprings 74 for frictional engagement with the well casing and outwardmovement can be limited by tangs 75, 76 which engage bands 77 and 78around the cage member 70. The drag blocks 73 function to resist bothrotational and longitudinal movement of the cage member 70 within thecasing in a conventional manner.

A plurality of slip members 80, for example three, are carried by thecage member 70 and are pivotally attached to its upper end by links 81.The slip members 80 can have wickers or teeth 82 on their outerperipheries which are adapted to bite into and grip the Well casing toresist longitudinal movement in either direction. Inclined surfaces 83on the inner peripheries of each slip member 80 converge downwardly andinwardly toward the mandrel 11 and are complementary in shape to theinclined surfaces 60 on the expander cone 58 in a manner wherebyrelative movement between the expander cone 58 and the slip members 80will cause lateral shifting of the slip members. The links 81 havepinholes 84 and 85 which receive pivotal mounting pins 86 and 87engaging in each slip member 80 and in the cage member 70, respectively.The lower pinholes 85 are formed as slots to permit each slip member 80to move outwardly while still being supported by the cage member 70. Theupper end of each link 81 has an upwardly extending shoulder orprojection 88 which engages in a radially extending recess 89 in eachslip member 80. Cantilever springs 90 can be attached to the cage member70 by screws 91 or other suitable fasteners, the springs having theirfree ends pressing against each link 81. The inward biasing force ofeach spring 90 is transferred to a respective slip member 80 through theshoulder 88 on each link 81 and through the upper pin 86 to hold theslip members in their normally retracted positions as shown in FIGURE1B. It will be appreciated that since the spring force is applied to twospaced points on each slip element 80, viz., the pin hole 84 and therecess 89, the slip elements will not tend to cant or cock in theirretracted positions and thereby be capable of hanging on a conduit wallprojection. Moreover, the lower slots or pinholes 85 permit enough lostmotion as the slip members 80- are moved outwardly so that the slipmembers can still be supported by the upper end of the cage member 70when they are in their expanded position.

To control relative longitudinal motion between the cage member 70 andthe mandrel 11, a clutch mechanism is provided, the clutch mechanismbeing referenced generally in the drawings by the numeral 93. The clutchmechanism 93 includes a split nut member 94, the nut member beingalternatively engageable with lower and upper cam portions 95 and 96,respectively, on the mandrel 11. The nut member 94 is preferablycomposed of four segments with opposite segments 97 having downwardlyfacing buttress form threads 98 as shown in FIG- URE 5, and the othertwo opposite segments 99 having an upwardly facing cam tooth 100. Bandsprings 101 or other suitable inward biasing means are received ingrooves 102 around the periphery of the nut member 94 to permit it toexpand while urging inward contraction. Downwardly extending lugs 103(FIGURE 1B) on the cage member 70 can engage between segments of the nutmember 94 so that the nut member can not rotate relative to the cagemember.

The upper cam portion 96 of the mandrel 11 can be a length of left-handthreads forming upwardly facing teeth 104 which are normally locatedabove the nut member 94. The mandrel teeth 104 are companion in form tothe teeth 98 on the nut segments 97. The lower cam portion on themandrel 11 includes an elliptically formed recess 105 in which the camtooth on each segment 99 can engage. The upper end of the recessdiverges downwardly and outwardly to form a shoulder 106 which engagesthe top surfaces of each cam tooth 100 on the segments 99. When theparts are in the positions shown in FIGURE 1B, the cage member 70 cannot move upwardly relative to the mandrel 11 as the packer 10 is loweredinto a well bore. Accordingly, the slip members 80 can not beprematurely set without deliberate rotation of the mandrel 11. As shownin FIGURE 4, the elliptical recess 105 opens on its opposite sides 107and 108 to the diameter of the mandrel 11. Thus it will be appreciatedthat rotation of the mandrel 11 a quarterturn relative to the cagemember 70 will cam or shift the segments 99 out of engagement with therecess 105 and free the mandrel for downward movement relative to thecage member 70'.

When the two cam tooth segments 99 are engaging in the mandrel recess105, the two threaded segments 9-7 of the nut member 94 are not engagingand are being held in expanded positions 'by the mandrel shoulder 106.However, downward movement of the mandrel 11 after its release as abovedescribed will cause the mandrel threads 104 to ratchet downwardlythrough the nut member 94, the lower inclined surfaces of the teeth 104urging all four nut segments in radially outward directions. Due to theform of the teeth 104 and 98 on the mandrel and on the opposed nutsegments 97, respectively, the threaded segments 97 can engage themandrel teeth 104 to trap the mandrel 11 in the lowermost position towhich it is moved. Upward movement of the mandrel 11 relative to thecage member 70 can then only be effected by right-hand rotation of themandrel which serves to unthread the mandrel teeth 104 upwardly and outof engagement with the nut segments 97.

To properly position the cam segments 99 relative to the ellipticalrecess 105 as the packer 10 is lowered into the well, a stud 110 can bethreaded into the stop ring 71 and engage a lug 111 which extendsdownwardly from the lower end of the cage member 70. With the stud 110engaging the lug 111, the mandrel 11 is properly oriented, rotationallyspeaking, so that the deep portions of the recess 105 are radiallyaligned with the cam segments 99 of the nut member 94. So positioned,the cam segments 99 can prevent upward movement of the cage member 70along the mandrel 11 until the cam segments are released.

OPERATION In operation, the well packer is assembled as shown in thedrawings and lowered on the tubing string 14 to a selected setting pointwithin the well casing P. During lowering, the drag blocks 73 slide infrictional engagement with the well casing wall. The packing structure22 is retracted and well fluids can bypass around the outside thereofand through the bypass passageways 30, 41 behind the packing structure.The cage member 70 can not move upwardly along the mandrel 11 due to theengagement of the cam tooth segments 99 of the nut member 94 within therecess 105 on the mandrel. Accordingly, the slip members 80 can not movetoward the expander cone 58 and be prematurely shifted outwardlythereby.

At setting depth, the mandrel can be torqued or turned by manipulationof the tubing string 14 at the earths surface to cause the cam toothsegments 99 to be shifted from engagement with the mandrel. With themandrel 11 thereby released for downward movement relative to the cagemember 70, lowering of the mandrel moves the expander cone 58 downwardlyand behind the slip members 80 to shift them outwardly as shown inFIGURES 2A and 2B. When the slip members actually engage the Wellcasing, the wickers or teeth 82 will bite into and grip the casing sothat further downward movement of the expander cone 58, the hydraulicmember 45 and of the compression sleeve is precluded. Continued downwardmovement of the mandrel 11 positions the seal element on the valve head31 adjacent to the inner surface of the lower sleeve portion 38 to closethe bypass passageway 30, 41 to fluid flow. The mandrel sleeve 16 alsoengages the thrust bearing 27 on the abutment ring 23.

Then the weight of the tubing string 14 can be let down on the mandrel11 to advance the abutment ring 23 along the compression sleeve 20toward the flange 21 to compress and expand the packing rings 24outwardly. As the mandrel moves downwardly, the mandrel threads 1G4ratchet downwardly through the nut member 94 and the threaded segments97 of the nut member trap the mandrel in its lowermost position to trapthe compression energy in the packing structure 22, When the packingstructure 22 is in firm sealing engagement with the well casing the wellpacker 10 is locked in a set condition. Inasmuch as the bore 12 throughthe mandrel 11 has at least the cross-sectional area of the tubingstring bore, an unrestricted access passage is provided to regions ofthe well bore below the packer from the earths surface.

Should fluid pressures in the tubing string 14 and below the packer 10exceed the pressures of fluids in the annulus above the packer, thehigher pressures act on the upper face of the hydraulic member as wellas upwardly on the lower face of floating piston member 62. The lowerfluid pressures are communicated through the mandrel sleeve ports 18,the upper portion of the bypass passageway 30, the grooves 68 behind thevalve head 31, and into the chamber 65 to act on the lower face 48 ofthe hydraulic member 45 and on the upper face of the floating pistonmember 62. The pressure difference will thus act over the area A asdownward force on the expander cone 58. The upward force on the pistonmember 62 due to pressure difference acting on the area B will cause thepiston member to engage the mandrel shoulder 47. The downward force onthe expander cone 58 increases the outward holding forces on the slipmembers 80 so that they will remain in firm and immovable engagementwith the well casing. Upward forces on the mandrel 11 due to highpressure from below are transferred by the nut segments 97 and the cagemember 70 directly to the slip members 80 which are gripping the wellcasing.

On the other hand, if pressure in the annulus above the well packer 10should exceed the tubing pressure, the floating piston member 62 canmove downwardly to engage the upper face 66 of the expander cone 58 andthe downward forces on the expander cone can exceed those being exertedupwardly on the hydraulic member 45 so that the net force is in adownward direction to increase the holding force on the slip members 80.Moreover, the pressure difference is acting on the expanded packingstructure 22 tending to move it downwardly and thus drive the expandercone downwardly. Thus it will be appreciated that the packer 10 isfirmly anchored to resist movement in either direction in the casingresponsive to pressure from above or below.

If it is desired to release the well packer 10, it is necessary torotate the mandrel 11 in a right-hand direction to unthread the mandrelteeth 104 upwardly and out of the nut member 94. Frictional resistanceto such rotation is minimized by thrust bearing 27 on the abutment ring23 which is axially loaded by the inherent tendency of the packing rings24 to retract. Movement of the mandrel 11 in an upward direction willposition the seal element 35 on the valve head 31 adjacent to the recess39 to open the bypass passageway 30, 41 for equalizing any existingpressure differentials across parts of the well packer. Of course,pressures on the cone holding hydraulic member 45 are equalized as wellas thoze across the floating piston member 62. With the bypasspassageway 30, 41 open, any sediment in the annulus and on top of thepacker can be washed away and full mandrel circulation or reversecirculation is permitted.

As the mandrel 11 moves upwardly, the compression force on the packingstructure 22 is relieved and it will inherently retract. Eventually themandrel shoulder 47 will engage the lower face 48 of the hydraulicmember 45 to pull the expander cone 58 from behind the slip members 80.As the expander cone 58 moves upwardly, the springs 90 will cause theslip members to retract from the casing and the well packer 10 is free.The lower end of the cage member '70 will engage the stop ring 71 on themandrel 11 and the various parts of the well packer 10 are in theirretracted positions for longitudinal movement in the well casing.

It will be appreciated that although the well packer 10 has been shownand described for compression setting, e.g., by applying the weight ofthe tubing string 14 to move the mandrel 11 downwardly and expand theslip elements 80 and the packing ring 24, it will be apparent that thetool can be inverted in its entirety and set in tension, if desired. Inthis case, the tubing string 14 can be coupled to the mandrel threads 15for lowering into the well bore. After releasing the clutch mechanism 94at setting depth, an upward strain can be taken on the tubing string 14to move the mandrel 11 upwardly for expanding parts of the well packer.High pressure in the annulus will act upwardly on the hydraulic member45 to increase the holding force on the slip elements 80 and highpressure below the well packer can moe the floating piston member 62into engagement with the expander cone 58. In the latter situation, theeffective pressure area B of the floating piston member 62 can beconstructed and arranged to exceed the effective pressure A of thehydraulic member 45 so that the net force is in an upward direction toincrease the holding force on the slip elements 80.

After the well packer 10 has maintained a set condition over aconsiderable length of time, it is possible that the packing rings 24can lose resiliency and be permanently deformed, in which case there canbe a decrease in the outward pressure being exerted by the expander cone58 on the slip elements 80. Accordingly, it may be desirable, as shownin FIGURE 7, to include a compression spring 112 surrounding the mandrel11 with its upper end pressing against the floating piston member 62 andits lower end pressing against the expander cone 58. The expander cone58 can be provided with an internal annular recess 113 for receiving thelower portion of the compression springs 112. The spring 112 is capableof exerting a predetermined magnitude of force on the expander cone whenthe parts of the packer are in set condition. In this manner, thecompression spring 112 can function to maintain holding force on theslip elements 80, even though the packing rings have relaxed, to aid inkeeping the well packer 10 anchored in the well casing.

A new and improved well packer has been disclosed for sealing off theannulus between two flow conductors in a well. The well packer is of thefull-bore, retrievable type having only a single anchoring mechanism yetwhich will remain immovable in a well although subjected to pressurefrom above or below. An integral bypass is provided which can beselectively operated for passing fluid through the packing element.Since certain modifications or changes may be made in the disclosedembodiment of the present invention without departing from the conceptsinvolved, it is intended that the appended claims cover all suchmodifications or changes falling within the true spirit and scopethereof.

What is claimed is:

1. A well packer for use in a well bore comprising: sleeve means havingan external recess and sealing means in said recess adapted to beexpanded against a well bore wall; a body member movable within saidsleeve means and providing a fluid passage space with said sleeve memberthrough which well fluids can flow from the exterior of said devicearound said sealing means; passage closing means between said sleevemeans and body member for selectively opening and closing said fluidpassage space; normally retracted anchor means shiftable outwardly ofsaid body member into engagement with the well conduit wall foranchoring said well packer in the well conduit; expander means movablerelative to said anchor means for shifting said anchor means outwardlyand for exerting force on said anchor means; hydraulic means connectedto said expander means and responsive to a pressure difference acrosssaid sealing means in its expanded condition for increasing the outwardforce on said anchor means to hold said anchor means engaged with thewell conduit wall; and other passage means around said closing means andseparate from said passage space for communicating well annuluspressures to said hydraulic means when said passage space closing meanscloses said passage space.

2. The well packer of claim 1 wherein said passage closing meansincludes a valve head on said body member and seal means on said valvehead engageable with a portion of said sleeve means.

3. The well packer of claim 2 wherein said other passage means islocated between said valve head and said body member.

4. The well packer of claim 2 wherein said valve head comprises a sleevemember attached to said body member for movement therewith, said sleevemember having an enlarged portion, said sealing means being on saidenlarged portion.

5. The well packer of claim 4 wherein said other passage means islocated between said sleeve member and said body member.

6. The well packer of claim 5 wherein said other passage means includesat least one groove extending longitudinally along said sleeve member.

7. A well packer comprising: sleeve means having a deformable sealingelement arranged for expansion to seal against a surrounding wellconduit wall; a tubular body member adapted for connection to a tubingstring, said body member being movable within said sleeve means; a fluidpassageway between said body member and sleeve member permitting flow offluids around said sealing element; passageway closing means betweensaid body member and sleeve member for selectively opening and closingsaid passageway; normally retracted slip members shiftable outwardly ofsaid body member into gripping engagement with a well conduit wall foranchoring said well packer in a well conduit; expander means movablerelative to said slip members for shifting them outwardly; hydraulicmeans connected to said expander means responsive to a pressuredifference across said sealing element in its sealing condition forexerting outward force on said gripping members, said hydraulic meansincluding a sleeve piston movable on said body member on one side ofsaid sealing element and responsive to fluid pressure in the well boreon one side; means on said body forming a chamber with said sleevepiston; and means for communicating fluid pressure in the well bore onthe other side of said sealing element with said chamber.

8. The well packer of claim 7 wherein said chamber forming meanscomprises an annular member between said sleeve piston and said bodymember; and seal means sealing between said annular member and saidsleeve piston.

9. The well packer of claim 8 wherein said annular member is movablealong said body member; and means to limit movement of said annularmember along said body member.

10. The well packer of claim 7 wherein said passageway closing meansincludes a valve head on said body member and seal means on said valvehead engageable with a portion of said sleeve means.

11. The well packer of claim 10 wherein said pressure communicatingmeans is located between said valve head and said body member.

12. The well packer of claim 10 wherein said valve head comprises asleeve member attached to said body member and movable therewith, saidsleeve member having an enlarged portion, said sealing means being onsaid enlarged portion.

13. The well packer of claim 12 wherein said pressure communicatingmeans includes at least one recess inside said sleeve member extendinglongitudinally along said body member.

14. The well packer of claim 7 further including a tubular membermovable relative to said body member for supporting said normallyretracted slip members; and means operable by manipulation of said bodymember for controlling relative movement between said tubular member andsaid body member.

15. The well packer of claim 14 further including linkage means forconnecting said normally retracted slip members to said tubular member,said linkage means including a lost-motion connection to permit saidtubular member to engage said slip members when said slip members areshifted outwardly.

.16. In a well packer adapted for use in a well bore, the combinationcomprising: a first member; means carried by said first member adaptedto seal off a well conduit; a second member movable relative to saidfirst member; normally retracted wall engaging means cooperable withsaid second member to resist movement of said second member within thewell bore; cage means movably mounted on said first member; link meanspivotally connecting said wall engaging means to said cage means, saidlink means including a lost-motion connection so that upon expansion ofsaid wall engaging means said cage means can engage said wall engagingmeans; and means engageable with said wall engaging means to retractsaid wall engaging means from the wall of the well bore.

17. In a well tool, the combination comprising: a first member; a secondmember movable relative to said first member; normally retracted wallengaging means cooperable with said second member for movement between afirst retracted position and a second wall engaging position, said wallengaging means in said second position functioning to resist movementwithin a well bore; cage means movably mounted on said first member;linkage means for connecting said wall engaging means to said cagemeans, said linkage means including a lost-motion connection to saidcage means to permit said wall engaging means to move to said secondposition while being supported by said cage means, said linkage meansfurther including means cooperable with said wall engaging means in saidfirst position to prevent pivotal movement of said wall engaging meansrelative to said first member.

18. In a well tool, the combination comprising: a body member; normallyretracted means shiftable outwardly of said body member; means forshifting said normally retracted means outwardly of said body member;cage means on said body member and adapted for supporting said normallyretracted means; linkage means pivotally connecting said normallyretracted means to said cage means, said linkage means including alost-motion connection whereby said normally retracted means can beshifted outwardly while being supported by said cage means; andresilient biasing means for urging said normally retracted means towardretracted positions.

19. The combination of claim 18 further including inclined surfaces onsaid cage means and normally retracted means for supporting engagementwhen said normally retracted means are shifted outwardly.

20. The combination of claim 19 further including a shoulder on saidlinkage means engaging said normally retracted means, when retracted,for preventing pivotal movement of said normally retracted meansrelative to said body member.

21. In a well tool, a mandrel; a cage member on said mandrel includingmeans for frictionally engaging the wall of a well conduit; lockingmeans between said cage member and said mandrel including first meansforming interlocking surfaces between said mandrel and cage member toprevent relative longitudinal movement in one direction, said firstmeans being disengageable upon relative rotation between said mandreland cage member where said relative rotation is less than 180; andsecond means including threaded interlocking connections on said mandreland cage member for preventing relative longitudinal movement in anopposite direction, one of said threaded interlocking connections beingdisplaced longitudinally from the other of said threaded interlockingconnections.

22. The well tool of claim 21 further including orienting meanscooperate between said cage means and said mandrel for positioning saidinterlocking surfaces for engagement, said orienting means beingoperable by move ment of said mandrel.

23. In a well tool, a mandrel; a cage member on said mandrel includingmeans for frictionally engaging the wall of a well conduit; and lockingmeans between said cage member and said mandrel to permit selectivepositioning of said mandrel and cage means including a segmented nutmember having at least two pairs of opposed segments, one of said pairsof opposed segments having surfaces capable of interlocking engagementin a recess in said mandrel to prevent relative longitudinal movement inone direction, said interlocking engagement being .disengageable uponrelative rotation between said mandrel and cage means of less than 180,the other of said pairs of opposed segments having threads formedthereon capable of threaded engagement with a threaded portion of saidmandrel for preventing relative longitudinal movement in an oppositedirection, said threaded engagement being releasable by relativerotation between said mandrel and cage means of more than 180.

24. A well packer apparatus comprising: a mandrel adapted for connectionto a pipe string; expander means and normally retracted slip meansshiftable by said expander means into gripping contact with a wellconduit wall in order to anchor against movement in the well conduit;expansible packing means for sealing off the annulus between saidmandrel and the well conduit wall; bypass passage means extendingbetween said mandrel and said packing means and between locations aboveand below said packing means; passage closing means on said mandrel forclosing off said bypass passage means when said packing means isexpanded; and hydraulic means connected to said expander means, saidhydraulic means including a piston member having upper and lowersurfaces exposed to fluid pressures in the well bore respectively belowand above said packing means to enable greater fluid pressures belowsaid packing means to exert downward force on said expander meanstending to shift said slip means outwardly.

25. A well packer apparatus comprising: a mandrel; expander means andslip means which can be shifted outwardly by said expander means intogripping engagement with a well conduit wall; packing means about saidmandrel which can be expanded into sealing engagement with a wellconduit wall; means cooperable with said mandrel for releasably lockingsaid packing means in expanded condition; bypass passage means betweensaid mandrel and said packing means for bypassing well fluid pastpacking means and to enable equalizing pressure differentials acrosssaid packing means; coengageable means for closing off said passagemeans when said packing means is expanded; piston means on said expandermeans having upper and lower surfaces, said upper surface being exposedto fluid pressure in the well bore below said packing means; and meansfor exposing said lower face of said piston means to fluid pressure inthe well bore above said packing means when said packing means is lockedin expanded condition.

References Cited UNITED STATES PATENTS 2,753,943 7/1956 Morgan 166-1392,917,114- 12/1959 Levendoski 166139 3,223,169 12/1965 Roark 1661293,253,656 5/1966 Brown 166--129 3,279,542 10/1966 Brown 166139 3,338,3088/1967 Elliston et a1. 166129 3,339,637 9/1967 Holden 166128 JAMES A.LEPPINK, Primary Examiner.

